Pulsed Neutron Monitoring of Hydraulic Fracturing and Acid Treatment

ABSTRACT

Hydraulic fracturing, acidizing and polymer injection using coiled tubing are commonly used techniques in wellbore completion. A pulsed neutron tool may be conveyed at the bottom of the coiled tubing to monitor the effectiveness of these operations by measuring the flow velocity of the borehole fluid of the annulus between the pulsed neutron tool and the borehole wall. Gamma rays resulting from Oxygen activation and/or Σ measurements are used for measuring the flow velocity.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims priority from U.S. Provisional Patent Application Ser. No. 61/508,899, filed on 18 Jul. 2011, incorporated herein by reference in its entirety.

BACKGROUND OF THE DISCLOSURE

1. Field of the Disclosure

This disclosure relates to well logging methods and apparatus and more particularly to nuclear well logging techniques and well completion monitoring techniques. Specifically, the disclosure is directed towards the use of pulsed neutron methods for monitoring flow rates in the borehole indicative of the effectiveness of hydraulic fracturing, acid treatment, and polymer treatment.

2. Description of the Related Art

Hydraulic fracturing of boreholes is a commonly used completion technique. The fracturing may be done in either open-hole or cased hole. In open-hole fracturing, the objective may be to increase the permeability of the earth formation over a fairly large interval. Hydraulic fracturing of cased holes is commonly done when it is desired to increase the permeability of the earth formation at different depths in the borehole. In cased-hole fracturing, the casing is perforated to produce weak points in the casing. Hydraulic fracturing, in both cases, is then carried out by increasing fluid pressure in the borehole.

Hydraulic fracturing can be performed using coiled tubing on multiple perforated intervals in a single stage. Hydraulic fracturing or “Frac” jobs often included multiple stages. The success of the frac job (e.g. number of intervals fractured and relative ability to produce/inject) can be determined by running production logs after the frac operation is complete.

In the process of fracture acidizing, an acid (usually HCl) is injected into a carbonate formation at a pressure above the formation fracture in pressure. The acid may form conductive channels in the formation that remain open without a propagation of the fracture process.

The term “matrix acidizing” refers to the treatment of a reservoir formation, with an acid. In sandstones, the acid reacts with soluble substances in the formation matrix and enlarges the pore spaces. In carbonate formations, the acid may dissolve the entire formation matrix. In both cases, the acidizing improves the formation permeability. Matrix acidizing is done at a pressure below the fracture pressure of the formation, which reduces possible reservoir damage.

Hydraulic fracturing and acidizing are typically carried out using fluids conveyed on coiled tubing. Another operation that may be carried out using fluids conveyed in coiled tubing is that of polymer injection. The objective of polymer injection may include sealing off highly permeable zones using a polymer. Due to the difficulties associated with injecting coiled tubing into a borehole and removing coiled tubing from the borehole, it may be desirable to monitor the effectiveness of the hydraulic fracturing, acidizing, and polymer injection substantially simultaneously with the fracturing, acidizing, and polymer injection operations. For the purposes of the present disclosure, hydraulic fracturing, acidizing operations, and polymer injection are referred to as formation modification operations. The present disclosure satisfies the need for monitoring such operations.

SUMMARY OF THE DISCLOSURE

One embodiment of the disclosure is a method of monitoring a formation modification operation in a borehole. The method includes: modifying a formation using a fluid conveyed into the borehole; making measurements indicative of a flow velocity of the fluid in an annulus between an instrument conveyed in the borehole and a wall of the borehole, the instrument including a radiation source; and estimating at least one parameter of the formation modification operation using the measurements at a plurality of positions along the borehole.

Another embodiment of the disclosure is an apparatus configured to monitor a formation modification operation in a borehole. The apparatus includes: a wellbore tubular configured to convey a fluid in the borehole and modify the formation; an instrument including a radiation source configured to be conveyed in the borehole and to make measurements indicative of a flow velocity of the fluid in an annulus between the instrument and a wall of the borehole; and a processor configured to: estimate at least one parameter of the formation modification operation using the measurements at a plurality of positions along the borehole.

Another embodiment of the disclosure is a non-transitory computer-readable medium product having instructions thereon that when read by a processor cause the processor to execute a method. The method includes: modifying a formation using a fluid conveyed into a borehole; making measurements indicative of a flow velocity of the fluid in an annulus between an instrument conveyed in the borehole and a wall of the borehole, the instrument including a radiation source; and estimating at least one parameter of the formation modification operation using the measurements at a plurality of positions along the borehole.

Another embodiment of the disclosure is a method of monitoring a formation modification operation in a borehole. The method includes: acquiring information relating to the formation modification using an instrument conveyed in the borehole penetrating the formation; and estimating at least one parameter of interest related to the formation modification using the acquired information, wherein the information is acquired at a plurality of positions along the borehole.

BRIEF DESCRIPTION OF THE FIGURES

The present disclosure is best understood with reference to the accompanying figures in which like numerals refer to like elements, and in which

FIG. 1 is an exemplary schematic diagram of an apparatus suitable for use with one embodiment of the present disclosure;

FIG. 2 is a schematic illustration of temporal signals (after normalization) measured at two spaced apart detectors;

FIG. 3 illustrates a situation where the near detector is immediately responsive to source activation;

FIGS. 4( a) and 4(b) illustrate changes in flow rate measured by a pulsed neutron instrument in a fractured portion of a borehole; and

FIG. 5 shows an exemplary apparatus suitable for monitoring of acid treatment.

DETAILED DESCRIPTION OF THE DISCLOSURE

FIG. 1 is an exemplary schematic diagram of an apparatus suitable for use with one embodiment of the present disclosure. This embodiment is directed to the evaluation of a fracturing operation being carried out in a previously perforated cased borehole. Shown therein is an earth formation 101 with a borehole 102. Inside the borehole is a casing 103. The casing includes two exemplary perforated sections. The first section includes perforations 105 a, 105 b, 105 c, and 105 d. The second perforated section includes perforations 115 a, 115 b, 115 c, and 115 d.

The fracturing operations may be carried out by fluid injected 163 into the borehole through a suitable wellbore tubular, such as coiled tubing 131. Suitable wellbore tubular may include, but are not limited to, coiled tubing, jointed tubulars, production tubing, and casing liners. An instrument, such as sensor unit 135, may be configured to estimate a parameter of interest in the annulus between the instrument and the wall of borehole 102. In one embodiment of the present disclosure, a sensor unit 135 is disposed at the end of the coiled tubing 131. Space is provided in the annulus between the sensor unit 135 and the inside of an enlarged section of the coiled tubing 131 for the injection fluid to flow into the borehole 102. The injected fluid 163 returns up the borehole as indicated by arrows 161 through the annulus between the coiled tubing 131 and the casing 103. In doing so, the returning fluid 161 flows by the perforations in the casing 103.

Those versed in the art and having benefit of the present disclosure would recognize that, as the returning fluid 161 flows by a perforation, some of the returning fluid would leak into the formation 101. Specifically, the more effective the fracturing of the formation 101 is at a perforation, the greater would be the amount of leakage of the borehole fluid 161 into the formation 101. Consequently, if the velocity of the returning fluid would be measured, it would steadily decrease in the uphole direction, and the magnitude of the decrease would be indicative of the fracturing. This velocity of the fluid in the annulus between the coiled tubing 131 and the casing 103 is measured by the sensor unit 135.

The sensor unit 135 may include a source of pulsed neutrons 151, and two or more gamma ray detectors 153, 155, 157, that are commonly referred to as the short spacing (SS), long-spacing (LS), and extra long spacing (XLS) detectors. In some embodiments, sensor unit 135 may include additional detectors, such as, but not limited to, one or more of: acoustic detectors, nuclear magnetic resonance detectors, electric field detectors, and magnetic field detectors.

A signal processor 122 is installed in the sensor 135. In one embodiment of the disclosure, the detector count rates are digitized downhole and are telemetrically transmitted to the surface through suitable conductors in wireline 133 to processing and archival storage unit at the surface (not shown). Alternatively, all the processing may be done by the downhole processor 122 and the results stored in a downhole memory for subsequent retrieval. In another embodiment of the disclosure, the processor, acoustic telemetry may be used to communicate data to the surface through the coiled tubing 131.

Activation of the pulsed neutron source 151 activates elemental oxygen-16 in the fluid flow 161. The gamma ray detectors 153, 155, 157 may detect the decay of the unstable isotope nitrogen-16.

In the present disclosure, the neutron source 151 may be ramped up to a maximum level over a ten second interval, maintained at a substantially constant value for twenty to forty seconds or so, and then ramped down over a ten second interval. Alternatively, the source activation and deactivation may be substantially instantaneous. Each of the detectors 153, 155, 157 may measure count rates or signals. Count rates from each of the detectors 153, 155, 157 are accumulated by a processor over a suitable time sampling interval. In one embodiment of the disclosure, the temporal sampling interval is 0.5 seconds. These count rates are made over a suitable energy level. In one embodiment of the disclosure, received gamma rays having energies above 3.0 MeV are counted. The upper limit of the energy window may be 8 MeV or so. The accumulated count rates define a temporal signal.

Turning now to FIG. 2, the basic principle of the method of the present disclosure are described. Shown are curves 201 and 203 that depict temporal signals measured at two detectors. The abscissa is time and the ordinate is the accumulated count rate over the temporal sampling interval. As noted above, the time sampling interval is typically 0.5 seconds. Note that in the plot, time increases to the left. The signal 201 corresponds to measurements made by a detector that is closer to the source than the detector that measured signal 203. Since the signals are the result of radioactive decay of nitrogen-16 with a half life of about 7.13 seconds, the absolute level of the signal measured by the farther detector will be less than the absolute level of the signal measured by the closer detector. In the plot shown in FIG. 2, suitable normalization of the signals has been done so that they appear to be of comparable amplitude. The spacing Ad between the near detector and the far detector is a known quantity. Hence by measuring the time delay At between signal 201 and signal 203, a velocity of flow v_(r) can determined by:

$\begin{matrix} {v_{r} = \frac{\Delta \; d}{\Delta \; t}} & (1) \end{matrix}$

This determined velocity v_(r) is a measurement of fluid velocity relative to the velocity of the logging tool v_(t). When the logging tool is stationary, then the velocity v_(r) will be the same as the actual fluid velocity. When the logging tool is in motion, then the actual fluid velocity v_(f) is given by:

v _(f) =v _(r) +v _(t)   (2)

where it is understood that the summation is a vector summation. For the remainder of the discussion of the method of the present disclosure, it is assumed that the logging tool is stationary, and that suitable correction for the velocity of motion of the tool can be made.

In one embodiment of the present disclosure, the time delay Δt is obtained by cross-correlation of the signals 201 and 203. When the near detector is sufficiently far from the source, the signal 201 corresponds to the activation of oxygen-16 to nitrogen-16 and the resulting gamma rays produced by decay of nitrogen-16. However, if the near detector is sufficiently close to the source (i.e. proximate to the source), it may respond immediately to the source activation due to gamma radiation produced by fast neutron inelastic scattering and thermal neutron capture events. This is depicted in FIG. 3 wherein, if the near detector D₁′ is within the region of inelastic or capture events denoted by 221, then the near detector D₁′ responds immediately to the source activation. The far detector D₂ responds to the nitrogen-16 after a time delay corresponding to fluid flow from the source position to the detector position D₂ and the associated distance Δd′. Those versed in the art would know other methods of estimating the travel time. This includes identifying the point of inflection of signals from the rising and falling edge of signals 201 and 203.

Turning now to FIGS. 4( a) and 4(b), the flow rate that would be measured by the method described above is illustrated by 401 as a function of position along the borehole 102. The decreases in the flow rate are indications that the perforated intervals have been satisfactorily fractured and that fluid is leaking out of the borehole 102. In contrast, a curve such as 403 would indicate that no fluid is leaking out of the borehole 102 at the perforations. The feature of the present disclosure is that this monitoring can be done in real time and remedial action can be taken to improve the fracturing. This may be done, for example, by increasing the fluid pressure.

Another embodiment of the disclosure may be used for monitoring of acid treatment real-time using a pulsed neutron logging instrument attached at the bottom of the coiled tube immediately below a flow port that allows acid treatment or diverter fluid to exit the tubing. FIG. 5 shows an open-hole 102 in which a sensor unit 135′ has been deployed. The sensor unit 135′ differs from the sensor unit 135 in that the pulsed neutron source 151 is above the gamma ray detectors 153, 155, 157. The port for acid injection or polymer injection is indicated by 145. The orientation or position of the port 145 is not critical for fracturing or acid injection. One benefit of having the sensor unit 135′ below the port 145 is that the sensor unit 135′ would not require a larger diameter bypass sub on the coiled tubing 131. This would allow access into smaller diameter wellbores or completions.

The sensor unit 135′ can detect and measure acid flow rate in a downhole direction using oxygen activation methods such as that described above with reference to the fracture monitoring device. Those versed in the art would recognize that acidization may increase the formation porosity, so that leakage of fluid into the formation may occur. In another embodiment of the disclosure, acid flow or exit into the formation may be detected using borehole Σ as a change in wellbore salinity (chloride in acid). An increase in formation Σ would be detected in intervals where the acid moved out into the formation. The movement of the acid may also be measured using oxygen activation of the oxygen in the water associated with the acid.

Coiled tubing may be placed at any point in the well, but for example, if the acid is injected near the top of the interval and enters the formation along the wellbore, then oxygen activation can be used to measure the velocity—as a continuous log or as stationary measurements—to determine the injection profile. In an alternate embodiment, coiled tubing could deployed to bottom of the interval, acid injected, and movement of the acid tracked by logging out of the well. This may be done at discrete locations or continuously. The pulsed neutron tool can be configured to measure up or down flow accordingly. Acid increases the formation sigma by increasing porosity and chloride effects. The injection intervals can be identified by the increases in measured Σ (as compared to a base log run in the same operation but prior to acid treatment). Acid-induced porosity increases can be determined by comparing Σ values before and after acid treatment. The porosity increase could be determined by comparison of the formation Σ before and after acid injection.

As noted above, It is sometimes desirable to seal off certain intervals in a borehole to restrict the flow of fluids into or out of the borehole. This may be done by injecting a polymer at the selected intervals. When a water-based polymer is used, the effectiveness of the sealing operation can be monitored by using the oxygen activation technique discussed above. In some embodiments, an interval of the borehole above and/or below the tool may be isolated using suitable well isolating tools, including, but not limited to, packers, bridge plugs, etc.

In another embodiment, the sensor unit 135 may be used to acquire information related to the formation modification operation. The acquired information may include information from a plurality of locations along the borehole. The acquired information may be used to estimate at least one parameter of interest related to the formation modification as understood by those of ordinary skill in the art. An additional operation may selected based on the estimated at least one parameter. Sensor unit 135 may be used to monitor and/or measure a change in the formation due to the additional operation. The change may or may not be in the at least one parameter of interest. The at least one parameter of interest may include one or more of: (i) an indicator of a degree of fracturing in the formation, (ii) a change in fluid flow in the annulus, and (iii) flow rate of fluid into the formation.

Implicit in the processing of the data is the use of a computer program implemented on a suitable computer-readable medium that enables the processor to perform the control and processing. The computer-readable medium may include ROMs, EPROMs, EAROMs, Flash Memories and Optical disks. The determined results of formation modification may be recorded on a suitable medium and used for subsequent processing upon retrieval of the BHA. The measurements (partially or fully processed) may be telemetered uphole. Alternatively, the formation fracture profiles and acidization profiles may be determined in situ and additional treatment may be made if warranted.

Those skilled in the art will devise other embodiments of the disclosure which do not depart from the scope of the disclosure as disclosed herein. Accordingly the disclosure should be limited in scope only by the attached claims. 

1. A method of monitoring a formation modification operation in a borehole, the method comprising: modifying a formation using a fluid conveyed into the borehole; making measurements indicative of a flow velocity of the fluid in an annulus between an instrument conveyed in the borehole and a wall of the borehole, the instrument including a radiation source; and estimating at least one parameter of the formation modification operation using the measurements at a plurality of positions along the borehole.
 2. The method of claim 1 wherein the formation modification operation is at least one of: (i) a hydraulic fracturing, (ii) an acid treatment, and (iii) a polymer injection.
 3. The method of claim 1 wherein the radiation source further comprises a pulsed radiation source, and making measurements indicative of the flow velocity of the fluid further comprises: irradiating the formation with the pulsed radiation source; obtaining a first temporal signal resulting from the irradiation at a first detector; obtaining at least one second temporal signal resulting from the irradiation at at least one second detector spaced apart from the first detector; and determining the flow velocity based on analysis of the first temporal signal, the at least one second temporal signal, and a distance between one of (A) the first detector and the at least one second detector, and (B) the source and the at least one second detector.
 4. The method of claim 1 wherein the at least one parameter of interest includes at least one of: (i) an indicator of a degree of fracturing in the formation, (ii) a change in fluid flow in the annulus, and (iii) flow rate of fluid into the formation.
 5. The method of claim 3 wherein the first temporal signal is selected from: (i) gamma rays resulting from nitrogen-16 and (ii) a cross section Σ of the fluid.
 6. The method of claim 3 wherein the first detector is proximate to the radiation source and is responsive immediately to inelastic and capture events resulting from the pulsed radiation, and wherein the at least one second detector is responsive to the produced gamma rays.
 7. The method of claim 3 wherein determining the flow velocity is based on a correlation between the first temporal signal and the at least one second temporal signal.
 8. The method of claim 1 further comprising: positioning a processor at a downhole location, wherein the processor is configured to estimate the at least one parameter using the measurements at a plurality of positions along the borehole; and performing a remedial action based on the at least one parameter.
 9. An apparatus configured to monitor a formation modification operation in a borehole, the apparatus comprising: a wellbore tubular configured to convey a fluid in the borehole and modify the formation; an instrument including a radiation source configured to be conveyed in the borehole and to make measurements indicative of a flow velocity of the fluid in an annulus between the instrument and a wall of the borehole; and a processor configured to: estimate at least one parameter of the formation modification operation using the measurements at a plurality of positions along the borehole.
 10. The apparatus of claim 9 wherein the formation modification operation is one of: (i) a hydraulic fracturing, (ii) an acid treatment, and (iii) a polymer injection.
 11. The apparatus of claim 9 wherein the at least one parameter of interest includes at least one of: (i) an indicator of a degree of fracturing in the formation, (ii) a change in fluid flow in the annulus, and (iii) flow rate of fluid into the formation.
 12. The apparatus of claim 9 wherein the radiation source further comprises a pulsed radiation source further configured to irradiate the earth formation with the pulsed radiation source; and wherein the instrument further comprises: a first detector configured to obtain a first temporal signal resulting from the irradiation; at least one detector spaced apart from the first detector configured to obtain at least one second temporal signal resulting from the irradiation; and wherein the processor is further configured to estimate the flow velocity based on analysis of the first temporal signal, the at least one second temporal signal, and a distance between one of (A) the first detector and the at least one second detector, and, (B) the source and the at least one second detector.
 13. The apparatus of claim 12 wherein the first temporal signal is selected from: (i) gamma rays resulting from nitrogen-16 and (ii) a cross section Σ of the fluid.
 14. The apparatus of claim 12 wherein the first detector is proximate to the source and is responsive to inelastic and capture events resulting from the pulsed radiation, and wherein said at least one second detector is responsive to the produced gamma rays.
 15. The apparatus of claim 9 wherein the processor is configured to estimate the flow velocity based on a correlation between the first and at least one second signal.
 16. The apparatus of claim 9 wherein the processor is further configured to perform a remedial action based on the at least one parameter.
 17. A non-transitory computer-readable medium product having instructions thereon that when read by a processor cause the processor to execute a method, the method comprising: modifying a formation using a fluid conveyed into a borehole; making measurements indicative of a flow velocity of the fluid in an annulus between an instrument conveyed in the borehole and a wall of the borehole, the instrument including a radiation source; and estimating at least one parameter of the formation modification operation using the measurements at a plurality of positions along the borehole.
 18. The non-transitory computer-readable medium product of claim 17 further comprising at least one of: (i) a ROM, (ii) an EPROM, (iii) an EEPROM, (iv) a flash memory, and (v) an optical disk.
 19. A method for monitoring a formation modification operation, the method comprising: acquiring information relating to the formation modification using an instrument conveyed in the borehole penetrating the formation; and estimating at least one parameter of interest related to the formation modification using the acquired information, wherein the information is acquired at a plurality of positions along the borehole.
 20. The method of claim 19, further comprising: performing an additional operation based on the at least one estimated parameter of interest.
 21. The method of claim 20, further comprising: estimating a change in the formation after the additional operation. 